Nanoparticle kinetic gas hydrate inhibitors

ABSTRACT

Inhibiting gas hydrate formation while transporting hydrocarbon fluids may include providing a kinetic gas hydrate inhibitor, adding the kinetic gas hydrate inhibitor to a fluid capable of producing gas hydrates, and transporting the fluid that comprises the kinetic gas hydrate inhibitor. Generally a kinetic gas hydrate inhibitor may include a heterocyclic compound comprising nitrogen, e.g., polyvinyl pyrrolidone).

CROSS-REFERENCE TO RELATED APPLICATIONS

The present application is a divisional of U.S. patent application Ser.No. 14/514,841 entitled, “NANOPARTICLE KINETIC GAS HYDRATE INHIBITORS,”filed on Oct. 15, 2014, which is a divisional of U.S. patent applicationSer. No. 13/343,820 entitled, “NANOPARTICLE KINETIC GAS HYDRATEINHIBITORS,” filed on Jan. 5, 2012, now U.S. Pat. No. 8,887,815, theentire contents of each of which are incorporated by reference hereinfor all purposes.

BACKGROUND

The present invention relates to methods of using kinetic gas hydrateinhibitors in subterranean operations.

Gas hydrates are a growing concern in oil or gas production at least inpart because gas hydrates can present flow assurance problems in onshorewells, offshore wells, and pipelines. Gas hydrates are a common form ofa unique class of chemical compounds known as clathrates, in which arigid, open network of bonded host molecules enclose, without directchemical bonding, appropriately sized guest molecules of anothersubstance. In the case of gas hydrates, water acts as the host molecule,enclosing gas molecules such as methane, thereby yielding ice-likecrystals of gas and water.

Gas hydrates normally are found in cold climates, in deepwaterenvironments, or at any point in a gas system where the gas experiencesrapid expansion. As this lattice expands and gains mass, it can blocktubings, flow lines, pipelines, or any conduit through which producedgas flows such as a drill string or a blow out preventer.

As deepwater drilling and production increases, the problems associatedwith hydrate formation may increase. Deepwater is an ideal breedingground for the growth of gas hydrates, and when these ice-like crystalsform in the circulating system, attempts to manage them can be costlyand dangerous. For the same reason, as operators search for hydrocarbonsin colder regions such as Siberia, Alaska, and Canada, hydratesincreasingly will become a cause of significant production problems.

Operators can take precautionary measures by reducing the wateravailable for gas hydrate formation. For example, after a pipeline forthe transportation of light hydrocarbons such as natural gas has beenrepaired, constructed, hydro-tested, or otherwise exposed to water, itis mandatory that water remaining in the pipeline be removed. Lighthydrocarbon gases are particularly susceptible to forming hydrates withwater, which can and often do reduce or block the flow of gases throughpipelines.

To solve gas hydrate problems, the industry traditionally usesthermodynamic chemistry to dissolve and inhibit hydrate formation. Gashydrates offer two distinct problems for the scientists and engineerswho design systems to mitigate the hydrate effect. The first problemconcerns dissolution. When a hydrate plug forms, it must be melted tounblock the transmission conduit. For example, if a hydrate plug formsat the mudline in a deepwater completion, the operator must find a wayto melt the ice plug in situ before production can proceed.

The second problem concerns inhibition. The goal is to prevent hydrateformation in the first place. However, to inhibit hydrate formation, theinhibitor must be present before a system reaches hydrate-formingconditions (e.g., low-temperature, high-pressure flow regimes). Thetraditional chemical approach to hydrate inhibition and dissolution hasbeen to add sufficient quantities of a thermodynamic inhibitor to theproduction system. “Thermodynamic inhibition” refers to the chemicals'abilities to suppress the point at which hydrates will form. Athermodynamic inhibitor lowers the temperature at which hydrates form(at a constant pressure), but it may also increase the pressure at whichhydrates form (at a constant temperature). By shifting the hydrateequilibrium toward higher pressure and lower temperature conditions,inhibitor chemicals make the water/gas system more resistant to hydrateformation.

However, mitigating the formation of gas hydrates with thermodynamicinhibitors requires significant quantities of the thermodynamicinhibitor. Methanol and glycols, usually ethylene glycol or triethyleneglycol, are traditionally used as thermodynamic inhibitors. Becauseglycols can significantly increase the cost of a subterranean operation,their use is usually limited to facilities that include a glycolrecovery or regeneration system. Further, because of the quantities ofthermodynamic inhibitors that need be present, the compositions andconcentrations of other additives in treatment fluids may be limited.

Thus, there is a need for improved methods of inhibiting gas hydrateformation in situ that requires less hydrate inhibitor and provides formore variability in the treatment fluid composition.

SUMMARY OF THE INVENTION

The present invention relates to methods of using kinetic gas hydrateinhibitors in subterranean operations.

In some embodiments, the present invention provides a method oftransporting hydrocarbon fluids that comprises providing a gas hydrateinhibitor that comprises poly(vinyl pyrrolidone); adding the gas hydrateinhibitor to a fluid capable of producing gas hydrates; and transportingthe fluid that comprises the gas hydrate inhibitor.

In other embodiments, the present invention provides a method ofproducing hydrocarbons that comprises providing a treatment fluidcomprising a base fluid and a gas hydrate inhibitor that comprisespoly(vinyl pyrrolidone); introducing the treatment fluid into a wellborepenetrating a subterranean formation; producing hydrocarbons from thesubterranean formation; and allowing the gas hydrate inhibitor toinhibit the formation of gas hydrates.

In still other embodiments, the present invention provides a method ofdrilling that comprises providing a drilling fluid comprising a basefluid and a gas hydrate inhibitor that comprises poly(vinyl pyrrolidone)nanoparticles having an average particle size less than about 1000 nm;drilling a wellbore using the drilling fluid, the wellbore penetratingat least one zone of a subterranean formation that has a temperature ofabout 5° C. or less; and allowing the gas hydrate inhibitor to inhibitgas hydrate formation in at least a portion of the wellbore.

The features and advantages of the present invention will be readilyapparent to those skilled in the art upon a reading of the descriptionof the preferred embodiments that follows.

DETAILED DESCRIPTION

The present invention relates to methods of using kinetic gas hydrateinhibitors in subterranean operations.

The present invention provides kinetic gas hydrate inhibitors thatrequire less inhibitor in a treatment fluid as compared to thermodynamicgas hydrate inhibitors. Further, the kinetic gas hydrate inhibitors mayallow for increased variability in the composition and concentrations ofadditives in treatment fluids according to some embodiments of thepresent invention. Kinetic gas hydrate inhibitors slow the formation andgrowth of gas hydrates thereby allowing for longer times to transportfluids and/or produce fluids from a wellbore.

In some embodiments, a treatment fluid may comprise, consist essentiallyof, or consist of a base fluid and kinetic gas hydrate inhibitors. Insome embodiments, kinetic gas hydrate inhibitors of the presentinvention may comprise, consist essentially of, or consist ofheterocyclic compound comprising nitrogen. As used herein, the term“heterocyclic compound comprising nitrogen” refers to any compound whosemolecules have a ring structure wherein at least one of the atoms in thering is a nitrogen atom.

Suitable heterocyclic compounds comprising nitrogen for use in thepresent invention may include, but not be limited to, polymerscomprising a vinyl pyrrolidone monomer unit, poly(vinyl pyrrolidone)homopolymers, poly(vinyl pyrrolidone) copolymers, poly(vinylpyrrolidone) blend polymers and copolymers, poly(vinyl pyrrolidone)branched polymers and copolymers, poly(vinyl pyrrolidone) crosslinkedpolymers and copolymers, and the like, or any combination thereof. Insome embodiments, a kinetic gas hydrate inhibitor of the presentinvention may comprise, consist essentially of, or consist of poly(vinylpyrrolidone). In some embodiments, kinetic gas hydrate inhibitors of thepresent invention may comprise, consist essentially of, or consist ofcrosslinked poly(vinyl pyrrolidone).

In some embodiments, kinetic gas hydrate inhibitors of the presentinvention may comprise, consist essentially of, or consist of poly(vinylpyrrolidone) nanoparticles. In some embodiments, poly(vinyl pyrrolidone)nanoparticles may have an average particle size ranging from a lowerlimit of about 1 nm, 5 nm, 10 nm, or 50 nm to an upper limit of about1000 nm, 500 nm, or 100 nm, and wherein the average particle size mayrange from any lower limit to any upper limit and encompass any subsettherebetween. In some embodiments, poly(vinyl pyrrolidone) nanoparticlesmay have an average particle size of 1000 nm or less. In someembodiments, poly(vinyl pyrrolidone) nanoparticles may have an averageparticle size of 400 nm or less.

Suitable poly(vinyl pyrrolidone) nanoparticles for use in conjunctionwith the present invention may include, but not be limited to,VIVIPRINT™ 540 (11% crosslinked poly(vinyl pyrrolidone) by weight water,available from International Specialty Products). In some embodiments,preferred crosslinkers may be chosen based on environmental regulationsin a region of interest, e.g., degradability.

In some embodiments, kinetic gas hydrate inhibitors of the presentinvention may comprise, consist essentially of, or consist of poly(vinylpyrrolidone) according to any embodiment described herein and rubberlatex. In some embodiments, kinetic gas hydrate inhibitors of thepresent invention may comprise, consist essentially of, or consist ofpoly(vinyl pyrrolidone) and rubber latex nanoparticles. One of ordinaryskill in the art will recognize the suitability of a nanoparticle sourcecomprising rubber latex where use of a drilling fluid may be subject toenvironmental restrictions, and should make appropriate adjustments tothe compositions or methods of the present invention. A variety ofnanoparticle sources comprising rubber latex may be used in conjunctionwith the present invention, including both synthetic and natural rubbersin latex form, where such rubber latexes are commercially available asaqueous dispersions and/or emulsions.

In some embodiments, kinetic gas hydrate inhibitors of the presentinvention may comprise, consist essentially of, or consist of poly(vinylpyrrolidone) according to any embodiment described herein andemulsion-polymerized copolymers of 1,3-butadiene and styrene. In someembodiments, kinetic gas hydrate inhibitors of the present invention maycomprise, consist essentially of, or consist of poly(vinyl pyrrolidone)and nanoparticles of emulsion-polymerized copolymers of 1,3-butadieneand styrene. Suitable nanoparticles of emulsion-polymerized copolymersof 1,3-butadiene and styrene for use in conjunction with the presentinvention may include, but not be limited to, TECHWAX™ FL250 (about 68%of emulsion-polymerized copolymers of 1,3-butadiene and styrene byweight water, available from Techwax, Ltd.).

In some embodiments, kinetic gas hydrate inhibitors of the presentinvention may comprise, consist essentially of, or consist of poly(vinylpyrrolidone) according to any embodiment described herein andanti-agglomerates. Suitable anti-agglomerates for use in conjunctionwith the present invention may include, but not be limited to,zwitterionic surfactants, zwitterionic polymers, amphoteric polymers,alkylamide surfactants, polypropoxylates, and the like, or anycombination thereof.

In some embodiments, kinetic gas hydrate inhibitors of the presentinvention may comprise, consist essentially of, or consist of polyvinylpyrrolidone) according to any embodiment described herein, rubber latexaccording to any embodiment described herein, and emulsion-polymerizedcopolymers of 1,3-butadiene and styrene according to any embodimentdescribed herein.

It should be noted that when “about” is provided at the beginning of anumerical list, “about” modifies each number of the numerical list. Itshould be noted that in some numerical listings of ranges, some lowerlimits listed may be greater than some upper limits listed. One skilledin the art will recognize that the selected subset will require theselection of an upper limit in excess of the selected lower limit.

In some embodiments, kinetic gas hydrate inhibitors of the presentinvention may be included in the treatment fluid in an amount rangingfrom a lower limit of about 0.0025%, 0.01%, 0.1%, or 0.5% to an upperlimit of about 5%, 1%, or 0.1% by volume of the treatment fluid, andwherein the amount of kinetic gas hydrate inhibitors may range from anylower limit to any upper limit and encompass any subset therebetween.

Suitable base fluids for use in conjunction with the present inventionmay include, but not be limited to, oil-based fluids, aqueous-basedfluids, aqueous-miscible fluids, water-in-oil emulsions, or oil-in-wateremulsions. Suitable oil-based fluids may include alkanes, olefins,aromatic organic compounds, cyclic alkanes, paraffins, diesel fluids,mineral oils, desulfurized hydrogenated kerosenes, and any combinationthereof. Suitable aqueous-based fluids may include fresh water,saltwater (e.g., water containing one or more salts dissolved therein),brine (e.g., saturated salt water), seawater, and any combinationthereof. Suitable aqueous-miscible fluids may include, but not belimited to, alcohols, e.g., methanol, ethanol, n-propanol, isopropanol,n-butanol, sec-butanol, isobutanol, and t-butanol; glycerins; glycols,e.g., polyglycols, propylene glycol, and ethylene glycol; polyglycolamines; polyols; any derivative thereof; any in combination with salts,e.g., sodium chloride, calcium chloride, potassium chloride, calciumbromide, zinc bromide, potassium carbonate, sodium formate, potassiumformate, cesium formate, sodium acetate, potassium acetate, calciumacetate, ammonium acetate, ammonium chloride, sodium bromide, ammoniumbromide, sodium nitrate, potassium nitrate, ammonium nitrate, ammoniumsulfate, calcium nitrate, sodium carbonate, and potassium carbonate; anyin combination with an aqueous-based fluid, and any combination thereof.Suitable water-in-oil emulsions, also known as invert emulsions, mayhave an oil-to-water ratio from a lower limit of greater than about50:50, 55:45, 60:40, 65:35, 70:30, 75:25, or 80:20 to an upper limit ofless than about 100:0, 95:5, 90:10, 85:15, 80:20, 75:25, 70:30, or 65:35by volume in the base treatment fluid, where the amount may range fromany lower limit to any upper limit and encompass any subsettherebetween. Examples of suitable invert emulsions include thosedisclosed in U.S. Pat. Nos. 5,905,061, 5,977,031, and 6,828,279, each ofwhich are incorporated herein by reference. It should be noted that forwater-in-oil and oil-in-water emulsions, any mixture of the above may beused including the water being and/or comprising an aqueous-misciblefluid.

In some embodiments, treatment fluids of the present invention may havea density ranging from about 7 lbs/gallon to about 22 lbs/gallon.

In some embodiments, treatment fluids of the present invention mayinclude additives. Suitable additives for use in conjunction with thepresent invention may include, but not be limited to, salts; weightingagents; inert solids; fluid loss control agents; emulsifiers; dispersionaids; corrosion inhibitors; emulsion thinners; emulsion thickeners;viscosifying agents; gelling agents; high-pressure, high-temperatureemulsifier-filtration control agents; surfactants; particulates;proppants; gravel particulates; lost circulation materials; foamingagents; gases; pH control additives; breakers; biocides; crosslinkers;stabilizers; chelating agents; scale inhibitors; thermodynamic gashydrate inhibitors; second kinetic gas hydrate inhibitors; mutualsolvents; oxidizers; reducers; friction reducers; clay stabilizingagents; and the like; or any combination thereof. One skilled in the artshould understand the applicability, appropriate concentrations, andcompatibility issues of the various additives for a given application.By way of nonlimiting example, high concentrations of multivalent saltsmay adversely effect the efficacy of kinetic gas hydrate inhibitorsdescribed herein and should be considered when formulating a treatmentfluid according to some embodiments of the present invention.

Some embodiments may involve inhibiting gas hydrate formation usingkinetic gas hydrate inhibitors described herein. Some embodiments of thepresent invention may involve using kinetic gas hydrate inhibitorsdescribed herein in conjunction with transporting hydrocarbon fluids,storing hydrocarbon fluids, and/or producing hydrocarbon fluids.

Some embodiments of the present invention may involve adding kinetic gashydrate inhibitors described herein to a fluid capable of producing gashydrates. One skilled in the art should understand the fluidcompositions that are capable of producing gas hydrates. By way ofnonlimiting examples, high-pressure methane and liquid water maycondense to form gas hydrates at temperatures below about 5° C.

In some embodiments, fluids capable of producing gas hydrates may behydrocarbon fluids comprising water. In some embodiments, fluids capableof producing gas hydrates may be hydrocarbon fluids comprising at leasttrace amounts of water. In some embodiments, fluids capable of producinggas hydrates may be light hydrocarbons (e.g., methane) comprising atleast trace amounts of water.

Some embodiments of the present invention may involve transporting afluid capable of producing gas hydrates and comprising kinetic gashydrate inhibitors described herein. In some embodiments, transportingfluids capable of producing gas hydrates and comprising kinetic gashydrate inhibitors described herein may be through wellbores, throughpipelines (above and/or ground), or any combination thereof. In someembodiments, transporting fluids capable of producing gas hydrates andcomprising kinetic gas hydrate inhibitors described herein may be from asubterranean formation to the surface of a wellbore and/or to apipeline. As used herein, the term “pipeline” refers to a tube or systemof tubes used for transporting hydrocarbon fluids from the field (e.g.,a wellbore) or gathering system to another location, e.g., a refinery.

In some embodiments, transporting fluids capable of producing gashydrates and comprising kinetic gas hydrate inhibitors described hereinmay be at reduced temperatures, e.g., about 5° C. or below.

Some embodiments of the present invention may involve storing a fluidcapable of producing gas hydrates and comprising kinetic gas hydrateinhibitors described herein. In some embodiments, storing fluids capableof producing gas hydrates and comprising kinetic gas hydrate inhibitorsdescribed herein may be at reduced temperatures, e.g., about 5° C. orbelow.

Some embodiments of the present invention may involve using kinetic gashydrate inhibitors described herein in conjunction with subterraneanoperations. Such operations may include, but are not limited to,drilling operations, lost circulation operations, stimulationoperations, sand control operations, completion operations, acidizingoperations, scale inhibiting operations, water-blocking operations, claystabilizer operations, fracturing operations, frac-packing operations,gravel packing operations, wellbore strengthening operations, sagcontrol operations, and the like. The methods and compositions of thepresent invention may be used in full-scale operations or pills. As usedherein, a “pill” is a type of relatively small volume of speciallyprepared treatment fluid placed or circulated in the wellbore.

Some embodiments may involve adding kinetic gas hydrate inhibitorsdescribed herein to treatment fluids. Some embodiments may involvetreating a subterranean formation with treatment fluids comprisingkinetic gas hydrate inhibitors described herein. Some embodiments mayinvolve introducing treatment fluids comprising kinetic gas hydrateinhibitors described herein into a wellbore penetrating a subterraneanformation. Some embodiments may involve producing hydrocarbon fluidscomprising kinetic gas hydrate inhibitors described herein from asubterranean formation.

Subterranean formation suitable for using compositions and methods ofthe present invention may include, but not be limited to, formationshaving at least one zone about 5° C. or less, more preferably formationshaving at least one zone about −10° C. or less, deep sea formations,formations comprising permafrost, and the like, or any combinationthereof.

Pipelines suitable for using compositions and methods of the presentinvention may include, but not be limited to, pipelines having at leasta portion of pipeline being about 5° C. or less, more preferablyformations having at least one zone less than about −10° C., pipelinesat least partially located in deep sea areas, pipelines at leastpartially located in arctic areas (e.g., at least portions of Alaska,Canada, Russia, Siberia, and similar regions), and the like, or anycombination thereof. Further, suitable pipelines may be at least in partabove ground, below ground, underwater, or any combination thereof.

Therefore, the present invention is well adapted to attain the ends andadvantages mentioned as well as those that are inherent therein. Theparticular embodiments disclosed above are illustrative only, as thepresent invention may be modified and practiced in different butequivalent manners apparent to those skilled in the art having thebenefit of the teachings herein. Furthermore, no limitations areintended to the details of construction or design herein shown, otherthan as described in the claims below. It is therefore evident that theparticular illustrative embodiments disclosed above may be altered,combined, or modified and all such variations are considered within thescope and spirit of the present invention. The invention illustrativelydisclosed herein suitably may be practiced in the absence of any elementthat is not specifically disclosed herein and/or any optional elementdisclosed herein. While compositions and methods are described in termsof “comprising,” “containing,” or “including” various components orsteps, the compositions and methods can also “consist essentially of” or“consist of” the various components and steps. All numbers and rangesdisclosed above may vary by some amount. Whenever a numerical range witha lower limit and an upper limit is disclosed, any number and anyincluded range falling within the range is specifically disclosed. Inparticular, every range of values (of the form, “from about a to aboutb,” or, equivalently, “from approximately a to b,” or, equivalently,“from approximately a-b”) disclosed herein is to be understood to setforth every number and range encompassed within the broader range ofvalues. Also, the terms in the claims have their plain, ordinary meaningunless otherwise explicitly and clearly defined by the patentee.Moreover, the indefinite articles “a” or “an,” as used in the claims,are defined herein to mean one or more than one of the element that itintroduces. If there is any conflict in the usages of a word or term inthis specification and one or more patent or other documents that may beincorporated herein by reference, the definitions that are consistentwith this specification should be adopted.

The invention claimed is:
 1. A method of transporting hydrocarbonfluids, the method comprising: providing a kinetic gas hydrate inhibitorthat comprises a rubber latex and a heterocyclic compound comprisingnitrogen; adding the kinetic gas hydrate inhibitor to a fluid capable ofproducing gas hydrates; and transporting the fluid that comprises thekinetic gas hydrate inhibitor.
 2. The method of claim 1, wherein atleast a portion of the heterocyclic compound comprising nitrogen iscrosslinked poly(vinyl pyrrolidone).
 3. The method of claim 1, whereinthe kinetic gas hydrate inhibitor further comprises emulsion-polymerizedcopolymers of 1,3-butadiene and styrene.
 4. The method of claim 1,wherein the kinetic gas hydrate inhibitor is about 0.0025% to about 5%by volume of the fluid.
 5. The method of claim 1, wherein transportingoccurs in a wellbore.
 6. The method of claim 1, wherein transportingoccurs in a pipeline.
 7. The method of claim 1, wherein at least aportion of transporting occurs at about 5° C. or less.